Method and system for monitoring moving elements

ABSTRACT

An apparatus and method for sensing a rotational parameter of a rotating member of a downhole pumping system. The apparatus is capable of detecting motor rotation and pump operating conditions and includes control systems for methods utilizing the rotational parameters to control the operation of the downhole pumping system.

BACKGROUND OF THE DISCLOSURE Field of the Disclosure

Embodiments of the present disclosure to downhole pumping systems usedto pump fluids from wells and, and more particularly, to a method andsystem for detection, correction and monitoring of the rotationalmovement of an electric motor as part of a downhole pumping system.

Description of the Related Art

Electric Submersible Pumping (ESP) is a widely used method of artificiallift, whereby a pump and an electric motor are deployed in a boreholeand are used to bring fluids, including liquid and gas, to the surface.Artificial lift is necessary when the natural well pressure isinsufficient to do so by itself. The motor is powered via a length ofelectric cable rising to surface and thence connected to controlequipment. Injection pumping is also used in the art whereby a pump andelectric motor deployed in a borehole are used to inject fluids andsolids (such as proppants) into a formation. Although induction typemotors are dominant in the field of ESPs, permanent magnet motors arebecoming more common and have a different set of problems to be solvedto ensure safe and reliable control.

It has been found that achieving reliable operation of ESPs and optimumproduction is greatly assisted by downhole gauges. A typical gauge willinclude a sensor to measure the motor internal temperature, which allowsthe motor to be protected by stopping it if it gets too hot. Such agauge will include a sensor to measure the pump intake pressure, whichis the reservoir flowing pressure (pressure where fluid enters theborehole) referred to the intake. Controlling the pump to regulateintake pressure therefore regulates production. If the intake pressuredrops too low it indicates insufficient fluid above the intake, with thepossibility for the pump to run dry. This warning allows the pump to bestopped or slowed down using the surface control equipment. Lesscommonly, despite its benefits, a discharge pressure sensor is fitted.This discharge pressure sensor gives the pressure of the fluid columnabove the pump and allows the pressure head across the pump (thedifference of discharge and intake pressures) to be determined.

The process of installing a downhole pumping system is complex andentails several steps at which a three-phase power electrical joint,typically comprised of a connector, bolted or spliced must be made. Overmany decades of experience there still remains a significant probabilitythat the motor will turn in the wrong direction when first started dueto mis-phasing of the three-phase power electrical joint. Even with bestpractice the possibility of incorrect rotation must be allowed for.

Another important aspect of controlling downhole pumping systems is thecontrolling of the speed of the motor. It is known in the art thatmeasuring and reporting the angle of the rotating shaft of the motor isa very important parameter for robust and efficient control of permanentmagnet motors. Most such control methods use techniques from the knownbroad family of vector control algorithms. In some submersible pumpingapplications, the angle must be estimated in the drive from surfacevoltage and current using an algorithm known in the art as an observeror estimator. Operating a drive using estimated angle is also known assensorless control. In other industrial applications, such as robotics,it is usually feasibly to connect an angle encoder to the shaft and notrely on sensorless control, as this gives the maximum robustness torapid changes of load. However, in downhole pumping systems fitted witha conventional downhole gauge, the downhole gauges do not have thebandwidth to transmit shaft angle at a sufficiency high rate for sensorcontrol.

When no gauge is fitted, then at start up, or after a restart, it isnecessary to wait for the estimated time for fluid to arrive at surfacebefore it can be determined whether the pump is rotating in the correctdirection. It should be noted that such pumps used in in ESP systems arepredominantly centrifugal type pumps. The nature of such pumps is thateven when rotated in the wrong direction they will pump fluid until asignificant head is reached, albeit not normally enough to produce fluidat surface. Hence even when a discharge pressure measurement is made,and increasing pressure indicates fluid flow, it is not possible toimmediately determine whether the pump is rotating in the wrongdirection.

Another problem in the prior art, and in particular with unconventionalwells (shale formations for example), the ESP is often set in thesensibly horizontal section of the well. In such cases, the dischargepressure will not rise appreciably until the lifted fluid has enteredthe non-horizontal section, further delaying the ability to detectreverse rotation of the pump.

One practical result of a pump starting in the reverse direction iswasted time, which is very costly considering all the personnel andequipment tied up while waiting to know if the equipment is operatingcorrectly or if it has to be recovered from the well. These costs areeven higher for offshore operations, but often there is a further issueoffshore. Typically, much larger pumps are used, and the pump bearingsexperience high rubbing loads when running reversed. These can lead topremature failure and large expense in lost production and workover toreplace the pump.

In unconventional wells or wells that produce a lot of sand, it isimportant not to stop a running motor unless absolutely necessary. Thesewells contain much debris which is pumped up into the production tubing.When the pump stops, the debris falls back down the production tubingand into the pump and can cause it to seize or otherwise become damaged.Unconventional wells are typically deep and workover (repair) costs areextremely expensive. During start-up, a method that shortens the time todiscovering reverse rotation and correcting it greatly reduces theinitial amount of debris that can fall back down the production tubingand into the pump.

Progressive cavity pumps (PCPs) are another type of pump that can bedriven by electric motors in ESP systems, with the motor and pump beingdeployed in the borehole. PCPs are positive displacement and operateequally well in either sense of rotation in terms of pumping capability.Reverse rotation at start has the almost immediate effect of running thepump dry unless fluid has previously entered the production tubing thatthe pump is discharging into. Of course, once the fluid from theproduction tubing has been pumped out into the wellbore the PCP will bepumped dry. It is well known that a PCP will typically be damaged withina couple of minutes when run dry.

There is clearly a need for an improved means of detecting reverserotation of an ESP system at start up and the capability of acting on itpromptly. The present disclosure described herein below provides methodand apparatus to accomplish this and additional benefits for ESPoperations, independent of motor type and surface drive type.

SUMMARY OF THE DISCLOSURE

In accordance with some aspects of the present disclosure, systems andmethods related to a novel downhole pumping system are disclosed.Various embodiments of a downhole pumping system incorporating arotational movement sensor and control system are disclosed.

According to one aspect of the present disclosure, the downhole pumpingsystem includes an electrical submersible pump assembly that includes amotor, a shaft, a pump, and at least one sensor system positioned tomeasure a rotational parameter of the shaft. The system includes aprocessing system to determine a measurement of the rotational parameterand determines if the shaft is rotating, the direction of rotation, thespeed of rotation and the acceleration of rotation of the shaft. Thesystem may include a control system to control the rotational movementof the shaft in accordance with the rotational parameter.

According to another aspect of the present disclosure, a method ofcontrolling a downhole pumping system is disclosed. The method includesa desired rotational direction of the shaft and determining a rotationalparameter of the shaft from the at least one sensor system includingdetermining if the shaft is rotating, in which direction the shaft isrotating, the speed that the shaft is rotating and the acceleration ofthe shaft. The method further includes controlling the rotation of theshaft based on the rotational parameter and the desired rotationaldirection.

According to yet another aspect of the present disclosure, a methoddetermining a condition of the downhole pumping system is disclosed. Themethod includes determining whether the pump is in a stalled condition,a backspin condition, a speed fluctuation condition, a stuck condition,a stopped condition, or a constant speed condition.

Further areas of applicability will become apparent from the descriptionprovided in this disclosure. It should be understood that the disclosureand specific examples provided are for illustrative purposes and do notlimit the scope of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above-recited features of the presentdisclosure can be understood in detail, a more particular description ofthe disclosure, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this disclosure and are therefore not to beconsidered limiting of its scope, for the disclosure may admit to otherequally effective embodiments.

FIG. 1 is a schematic representation of a downhole pumping system inaccordance with the present disclosure.

FIG. 2 is a schematic representation of an electrical diagram of acommunication system of a downhole gauge.

FIG. 3 is an isometric view of a rotation sensor system in partialsection in accordance with an embodiment of the present disclosure.

FIG. 4 is an isometric view of a transmitter assembly of a rotationsensor in accordance with an embodiment of the present disclosure.

FIG. 5 is side view of a rotation sensor system in partial section inaccordance with an embodiment of the present disclosure.

FIG. 6 is an isometric view of a receiver of a rotation sensor system inpartial section in accordance with an embodiment of the presentdisclosure.

FIG. 7 is an isometric view of a receiver holder of a rotation sensorsystem in partial section in accordance with an embodiment of thepresent disclosure.

FIG. 8 is a graphical representation of the signal output a rotationsensor system in accordance with an embodiment of the presentdisclosure.

FIG. 9 is a circuit diagram of a Hall effect sensor in accordance withan embodiment of the present disclosure.

FIG. 10a is an illustration of a side view of an encoder of a rotationsensor system in accordance with an embodiment of the presentdisclosure.

FIG. 10b is an illustration of an end view of a receiver of an encoderof a rotation sensor system in accordance with an embodiment of thepresent disclosure.

FIG. 11 is circuit diagram of the receiver coils of an encoder of arotation sensor system in accordance with an embodiment of the presentdisclosure.

FIG. 12 is a flow chart of a method of operating a downhole pumpingsystem in accordance with an embodiment of the present disclosure.

DETAILED DESCRIPTION

In the following detailed description of the embodiments, reference ismade to the accompanying drawings, which form a part hereof, and withinwhich are shown by way of illustration specific embodiments by which theexamples described herein may be practiced. It is to be understood thatother embodiments may be utilized and structural changes may be madewithout departing from the scope of the disclosure.

Referring to FIG. 1, there is shown a typical downhole pumping systeminstalled in a wellbore. As is known, a borehole drilled in an earthformation 1 may be lined with casing 2 cemented to the surroundingformation. A motor 10 is coupled to a pump 12 via a motor seal 11. Thepump discharge end 13 is attached to production tubing 3. Productionfluid (not shown) enters the well via perforations 4 in the casing 2 andenters the pump at its pump intake 14. The production tubing 3 runs upthe borehole through the wellhead 6 and on to surface productionfacilities. In a typical installation, motor 10 comprises a three-phasemotor and is powered via a cable 15 which comprises a three-conductorelectric cable, which runs up to surface alongside and clamped to theproduction tubing 3 in a manner well known in the art. The cable 15 thenpenetrates through the wellhead 6 and runs to a vented junction box 20.In the embodiment shown, surface electric power 21 is converted by driveunit 22 to a frequency and scaled voltage needed by the motor 10. Thescaled voltage is then increased to the actual voltage needed by themotor 10, allowing for voltage drop in the cable, by transformer 23. Theoutput of the transformer 23 is connected in the vented junction box 20to the cable 15. In other embodiments, older installations for example,drive unit 22 may simply comprise a switch-board that passes the supplyvoltage directly to the transformer via a controllable contactor andprotective fuses. In the current area of art, drive unit 22 ispreferably a variable speed drive as this permits optimization ofproduction and energy savings. A variable speed drive is in any caserequired for permanent magnet motors due to the need for synchronouscontrol. A controller 24, whether separate or incorporated within thedrive unit 22, can be used to stop and start the motor and potentiallyto reverse the motor rotational direction by switching phase connectionselectronically or by switchgear as will be discussed more fully hereinbelow.

In some wells, the casing 2 to production tubing 3 annulus is sealedabove the motor 10 to prevent gas entering the casing. The seal (notshown) is well known in the art and is typically referred to as apacker. In this particular case, the cable 15 has to make a furtherpenetration through the packer. It is well known in the art that cableelectrical connections are made on either side of the packer penetrator.

Still referring to FIG. 1, downhole gauge 30 is attached to the motor10. Downhole gauge 30 contains electronics and usually has connectionsfrom its interior into the motor 10, which can be oil-filled, and tosensors mounted outside the gauge unit. Such sensors can includevibration and internal temperature sensors. A temperature sensor 31 canbe fitted inside the motor 10 and connected to the downhole gauge 30,and a pressure sensor 32 to sense the pressure of the fluid surroundingthe gauge. It is known in the art that the measured pressure is easilyrelated to the pump intake pressure using estimated fluid density andthe vertical height (elevation) between the pressure sensor 32 and thepump intake 14. If required, a second pressure sensor 33 can be used,connected by a sense tube 34 to a port in the production tubingimmediately above the pump discharge end 13. This, again with a suitableknown adjustment for elevation, is the discharge pressure measurement.In practice, the adjustments in pressure are small and rarely made.

Considering now the practical aspects of connecting the motor 10 to thedrive unit 22, it can be seen that potential errors may be made in thesequence of phase connections at the motor, at any splices in the cable(not shown), at and below the well head penetration, and in the junctionbox 20. With the aforementioned downhole seal penetrator there existstwo more such connections wherein potential errors may be made. Sincethe motor 10 is fully enclosed and deployed in the well, there is nopossibility to check if connections have been swapped at some point inthe lengthy sequence of actions followed to install such a system. Sinceerrors are inevitably made, from time-to-time it is difficult to predictwhether the motor 10 will start in the correct rotational direction.Although the pumping system shown in FIG. 1 illustrates an ESP typepump, alternative pumps and pumping schemes (other than lifting) may beused without departing from the scope of the present disclosure. Forinstance, embodiments of the present disclosure are well suited for usewith injection pumping systems wherein the desired rotational directionof the motor will be opposite of that for a pumping system. In addition,the desired rotational direction of the motor will depend directly onthe configuration of the pump and motor, i.e. their relational mountingscheme. In addition, a progressive cavity pump (PCP) when reversed willindeed pump fluid from the production tubing into the well.

Referring now to FIG. 2, there is shown a depiction of a typical form ofa prior art communication system 51 in which data and power istransferred via the motor star point 18 of the motor windings 19. Thereare numerous providers of downhole gauges offering this type of systemand the following illustrative description is not limiting in its scope.

In the ideal case of a motor 10 that is perfect sinusoidally wound,surface electric power 21 (FIG. 1) that is a perfect sinusoidal drivevoltage and a balanced cable 15, the motor star point 18 voltage wouldbe zero with respect to ground 17. In practice, motor star point 18 issubject to voltage imbalances, voltage harmonics and transients from thevoltage switching action of drive 22 (FIG. 1) (if used).

Still referring to FIG. 2, a gauge surface unit 36 is connected viathree inductors 40 attached to the cable 15 at the secondary side oftransformer 23. The downhole gauge 30 is connected to the motor starpoint 18 by an inductor 41. Inductors 40 and 41 provide sufficientreactance at the motor electrical power frequencies to limit the highmotor voltages to a safe level within downhole gauge 30 and gaugesurface unit 36. AC or battery power is applied to local power supply 46which supplies direct current (DC) power between ground 17 and inductor40, typically on the order of 100 volts DC. Downhole power supply unit42 recovers the power between inductor 41 and ground 17 and converts itto voltages required by the remaining electronic equipment. Downholepower supply unit 42 preferably draws a steady current. Signalconditioning and digitizing unit 45, using techniques well known tothose practiced in the art, converts an analog output from temperaturesensor 31 and pressure sensor 32 to a digital form. Here a pressuresensor 32, such as a strain gauge device, and a temperature sensor 31,such as a thermocouple, are representatively shown as inputs todigitizing unit 45. Processor unit 43 receives the digital data fromdigitizing unit 45, and optionally processes it such as by calibrationand filtering, and packages the measurements and status information intotelemetry packets, which are then modulated by processor unit 43 andimpressed upon inductor 41 such as by known techniques of varying thesupply current according to binary ones and zeroes and communicated viaa telemetry system.

In gauge surface unit 36, demodulation unit 47 demodulates the gaugedata. Processor unit 48 validates the demodulated data and makes itavailable to controller 24 (FIG. 1) using a known serial connection anddata protocol such as Modbus. Depending upon the sophistication of thedrive 22, two-way communication may be implemented, with the possibilityto change the selection of gauge data being transmitted uphole in eachtelemetry frame via a telemetry system.

The communication system 51 of FIG. 2 circulates gauge power and data inloop 50, wherein gauge current flows equally through the three motorcable conductors of cable 15 and the motor windings 19. The currentreturns through a distributed ground 17, primarily comprising themetallic motor, seal and pump construction and the production tubing.Cable 15 may also typically comprise a metallic cable armor which alsoprovides an electrically conductive return path. This electricallyconductive metalwork is earthed at the wellhead 6 (FIG. 1) and alsowhere it may touch the casing 2 at various points in the borehole. Thewater content of the borehole fluid may also provide a return pathbetween this metalwork and the casing.

Still referring to FIG. 2, the voltage from the secondary side oftransformer 23 applied to the motor 10 is differential, that is it isdifferential between individual phases. There is no earth connection.The gauge power and communication is common mode, that is it is betweenthe phases as a whole and earth. In principle, there is no interactionbetween motor power and gauge power and data. In practice, and asdescribed above, the motor star point 18 is not at zero motor voltagedue to system imperfections. The large inductances of 19, 40 and 41 andthe high capacitance 16 of the cable conductors to ground act as alow-pass filter. The distributed earth is of variable quality. Hence thecommon mode telemetry system experiences interference. Overall theeffect of these factors is to severely restrict the gauge databandwidth, typically to on the order of 10 bits/s.

Now with reference to FIG. 3, there is shown the bottom end of arepresentative submersible motor 10 in partial section view of anembodiment of the present disclosure. As will be described in moredetail herein below, this embodiment advantageously utilizes the downhole gauge communications system described immediately herein above. Theparticular embodiment can be utilized with any motor 10, includingsubmersible, and it should be appreciated by those skilled in the artthat there are design and installation variations amongst the variousmanufacturers of these products which do not affect the scope of thisdisclosure.

One embodiment of a rotational sensor system 115 of the presentdisclosure is best described with reference to FIGS. 3, 4 and 5, whereinmotor shaft 100 of motor 10 passes the end turns of the motor winding101 (similar to motor windings 19 in FIG. 2) and is supported by bearing102. Motor shaft 100 can in some embodiments be hollow for the purposesof circulating the oil that fills the motor, though in some cases thisbenefit is foregone and the shaft is solid. Rotation transmitterassembly 103 is fastened to the end of the motor shaft 100. It isscrewed in to the end of the shaft and secured with a grub screw 110 (orset screw) or a pin as shown in detail in FIGS. 4 and 5, although othermeans of attachment may be made without departing from the scope of thepresent disclosure. In the embodiment shown, the rotational transmitterassembly 103 is fully round and smooth and so does not createappreciable drag as it rotates with the shaft. Rotational transmitterassembly 103 may advantageously be made of an essentially non-magneticmaterial such as stainless steel. Two magnets 111, 112 are inserted intoits end face exposing opposite polarities wherein magnet 111 is shownhaving a North polarity facing outward and magnet 112 is shown having aSouth polarity facing outward. Magnets 111, 112 are preferably spacedclose enough together that their flux passes from one to the other in aloop as will be more fully described herein below.

Receiver assembly 104 is secured to a stationary portion of the body ofmotor 10, and in this particular embodiment is secured by screw 105 intothe receiver assembly holder 108 (FIG. 7) and is held stationary withrespect to rotating motor shaft 100. Referring briefly to FIG. 6,receiver assembly coil 107 is wound on a former 106. Former 106 ispreferably comprised of a magnetic material such as ferrite, carbonsteel or bonded iron powder, in order to concentrate flux from therotational transmitter assembly 103. It should be appreciated by thoseskilled in the art that receiver assembly holder 108 may be comprised ofa non-magnetic material or a magnetic material shaped to enhance thesensitivity of the rotational transmitter assembly 103.

In operation, as the magnets 111, 112 of rotational transmitter assembly103 rotate on motor shaft 100 and pass the receiver assembly coil 107(FIG. 6), a small voltage (electromotive force) will be induced, as iswell known from elementary electromagnetic theory. The instantaneouspolarity of the voltage will depend on the polarity of the magnet (111or 112) facing the receiver assembly coil 107, the coil connection toreceiver circuitry and the handedness of the coil turns thereon.Referring to FIG. 8, there is shown representative output signals in theform of voltage signals versus time from the rotational sensor system115 for one revolution of motor shaft 100 in accordance to a certain setof connections as discussed herein above. With the motor shaft 100turning clockwise (typically with the convention of looking up hole orfrom the right in FIG. 3), output signal 120 shows a positive voltagefirst as one magnet passes over receiver assembly coil 107, followed bya negative voltage as the second magnet passes over the receiverassembly coil. Conversely with the motor turning anti-clockwise, outputsignal 121 shows a negative voltage first as one magnet passes receiverassembly coil 107, followed by a positive voltage as the second magnetpasses over the receiver assembly coil. By placing the magnets 111, 112close together, and within a typical range of operating speeds, thevoltage signals will appear as a doublet. In so doing, the doubletcannot be confused with the large gap in the time between positive andnegative pulses corresponding to the alternative but longer spacingbetween magnets around the circumference of rotational transmitterassembly 103. Simple circuitry (not shown) such as positive and negativevoltage comparators and logic gates as may be envisioned by one skilledin the art, that will detect the sequence of positive and negativevoltage signals, and their rate of occurrence. Depending on the detailsof the particular embodiment and the magnetic flux path, the signals maynot be simple doublets and can, for example, be positive or negativepulses. It should be appreciated that embodiments of the presentdisclosure advantageously provide a means of determining the rotationaldirection of shaft 100 as well as its rotational speed. Although therotational transmitter assembly 103 of the rotational sensor system 115is shown attached to motor shaft 100, it may be attached to any othershaft or rotating part of the ESP system such as a coupling or pumpshaft (not shown). It will further be appreciated that there are severalsimple variations of this embodiment. For example, the magnets may beinserted directly into holes drilled in the shaft end if the shaft ismade of non-magnetic material. In another example the magnets may beinstalled radially (transversely to the shaft axis) with an opposingradial receiver coil. In addition, and to improve signal strength, themagnetic reluctance of the transmitter-receiver circuit can be reducedby incorporating magnetic material such as steel within the transmitterbehind the magnets.

A further advantage of this particular embodiment of the presentdisclosure is that it only requires one wire connected to receiverassembly coil 107 of receiver assembly 104 to pass from the motor 10,which can be oil-filled, at borehole pressure into the gauge electronicsat atmospheric pressure. The other end of receiver assembly coil 107 canbe connected to the housing of downhole gauge 30 and so it uses theexisting metallic continuity to be accessible to the gauge electronics.In ordinary industrial applications known Hall effect sensors provideeffective receivers, but in the present application their submersion inoil at high downhole pressure and temperature can severely limit thelife of these components. In addition, several connections may be neededfor their operation, each being a potential point of failure. However,Hall sensors have the benefit that they respond to magnetic fluxindependent of the shaft speed, whereas a pickup coil electromotiveforce increases with shaft speed. Hall sensors can therefore beadvantageous at low rotational speeds, and their use falls within thescope of embodiments of the present disclosure.

Now referring to FIG. 9, there is shown a circuit diagram ofanembodiment of a Hall sensor 251 can be used in a novel manner toimplement the direction sensing with only two wires connected to thegauge. Hall sensor 251 is of the known linear type, such as may beobtained from Allegro MicroSystems LLC, in which in the absence of amagnetic field passing through the sensor, the output 252 sits atapproximately half the supply voltage on connections 253 and 254. Thesupply voltage is provided by the gauge and ordinarily the output 252would form a third connection to the gauge for measurement. The outputsignal voltage on output 252 will increase or decrease according to thepolarity of the magnetic flux passing through the sensor. However, inthe given embodiment, output 252 is connected to transistor 255 and(emitter load) resistor 256. When output 252 increases, the currentthrough resistor 256 will increase and conversely if output 252decreases, the current through resistor 256 will decrease. As will beevident to one ordinarily skilled in the art, the resistor 256 currentis drawn through the connections 253 and 254. Hence when magnetic fluxpasses through Hall sensor 251 the supply current will increase ordecrease according to its direction. In this way, only connections 253and 254 need to pass into the gauge electronics compartment. One ofthese connections can potentially make use of the equipment metalwork asa conductor. In a practical implementation the circuitry of FIG. 9 wouldbe encapsulated to provide protection from the motor oil andcontamination, using a material such as epoxy. Referring to FIG. 4, thesame axially mounted magnet 111, 112 configurations may be used, withthe Hall sensor 251 positioned in the same location as receiver assembly104 in FIG. 5. Alternatively, the magnets may be disposed radially onmotor shaft 100 and the Hall sensor 251 located radially opposite. Ithas been discovered that the idealized output signals 120 and 121 inFIG. 8 are readily achieved over a very wide speed range in such anembodiment.

In another embodiment, although not shown, a receiver assembly 104 whoseinductance is measured, such as by impedance measurement or by use asone of the frequency-determining elements in an electronic oscillator,which are methods known to one ordinarily skilled in the art, can beused to sense variation in the magnetic reluctance of the motor shaft100 caused by notches or other magnetically permeable variationspositioned thereon.

The embodiment of rotational sensor system 115 described immediatelyherein above is but a single embodiment of the present disclosure forimplementing an encoder signal falling within the scope of thisdisclosure that measures rotational parameters to provide informationrelevant to shaft rotation and speed. While it is an importantdiscovery, the particular embodiment of rotational sensor system 115discussed directly herein above does not however provide an incrementalor absolute shaft rotation angle. Such shaft angle information may beuseful in determining whether motor shaft 100 has moved betweenattempted starts. This information would be helpful in the event of astuck pump as will be described more fully herein below. Such angularposition information may also be useful, for example, if a higher-speedtelemetry system is available or for small motors where the drive itselfis placed downhole.

Referring now to FIGS. 10a and 10b , there is shown an embodiment of arotational sensor, or encoder, 201 of the present disclosure thatmeasures rotational parameters to provide information relevant to shaftrotation and speed as well as an absolute shaft angle encoder. A disccomprises a rotating transmitter 200 and is comprised of a magneticallypermeable material, wherein such magnetically permeable material mayinclude carbon steel, is attached to the end of motor shaft 100.Rotating transmitter 200 has an end face at an angle relative to thetransverse section of the motor shaft 100 In an alternative embodiment,rotating transmitter 200 may be incorporated into motor shaft 100 bysimply forming a suitable angled face across the end of the motor shaft.In addition, if it is desired to minimize drag, the angled end face maybe restored to its normal square end using a complementary wedge ofessentially non-magnetic material such as stainless steel. Best shownwith reference to FIG. 10b , receiver assembly 109, mounted in a mannersimilar to that described herein above with reference to receiverassembly 104, comprises four coils 107A, 1076, 107C, 107D opposing thetransmitter 200 wherein the coils are disposed evenly about thecircumference of the receiver assembly. It should be appreciated thatthe inductance of each coil 107A, 1076, 107C, 107D will vary with itsdistance, from the face of the transmitter 200, or the gap formedtherebetween, which varies sinusoidally with shaft rotation. Inoperation, and with reference to any two adjacent coils, the inductanceof one will vary in sympathy with the sine of the shaft angle and theother will vary in sympathy with the cosine of the shaft angle. In suchan embodiment of the present disclosure, using the output of the sineand cosine, the absolute shaft angle relative to a reference point mayreadily be deduced. With reference to coils that are diametricallyopposed on receiver assembly 109, their inductances will vary togetherbut will be 180 degrees apart, so as one inductance increases the otherwill reduce. Although the transmitter 200 of the encoder 201 is shownattached to motor shaft 100, it may be attached to any other shaft orrotating part of the ESP system such as a coupling or pump shaft (notshown).

Now referring to FIG. 11, a circuit diagram shows how the coils 107A and1076 may be wired in series as a half-bridge and driven by AC voltage,typically in the tens or hundreds of kilohertz range depending onanticipated shaft rotational speed. A similar circuit (not shown) may beused for coils 107C and 107D. The mid-point AC voltage will be amplitudemodulated as the shaft rotates and the inductances vary. This amplitudemodulated voltage is readily demodulated as in block 113 byrectification and low-pass filtering, giving the sine and cosine ofshaft angle from the respective pairs of coils. These signals may beconverted to angle by means of a phase locked loop well known in theprocessing of resolver signals and digital radio receivers.

Having regard to the limited bandwidth system of typical downhole gauges30 as hereinbefore outlined, it is not feasible to transmit the shaftangular position in real-time at a rate needed by variable speed drivesfor vector control. For example, a motor turning at 3600 rpm wouldtypically need at least ten readings per rotation or 600 measurementsper second to enable such control. However, utilizing embodiments of thepresent disclosure, the direction and speed can be transmitted every tenseconds or so and the shaft angle may be transmitted from time-to-timeas needed wherein such transmission rates are easily accommodated by thecommunication system 51 (FIG. 2) of existing downhole gauges 30 (FIG.1).

One particularly useful aspect of embodiments of the present disclosureincludes that during make-up of the downhole assembly at surface beforerunning into the borehole, the motor shaft 100 may be turned manuallyand the gauge readings from the encoder 201 or rotational sensor system115 can be used to confirm the correct measurement of direction.

Now referring to FIG. 12, there is a flowchart showing the operation ofan embodiment of the present disclosure with reference to the variousfigures described herein above. In step 300, drive 22 is set to outputthe motor voltage phase sequence to what is intended to be the forwardrotational direction, where forward rotational direction is the correctsense for pumping if the system is connected as intended or the oppositedirection if injection is intended. The drive can be of known vector orscalar type or a simple switchboard operating from a fixed power supply.As described herein above, the required direction of rotation will bedetermined by the pump and motor configuration as well as the desiredeffect, i.e. lifting or injection. In step 301, downhole gauge 30 is putinto start-up mode where it transmits status data bits for direction ofrotation and whether the motor shaft 100 of motor 10 is rotating. Asdescribed herein above, downhole gauge 30 may also transmit pressure andtemperature measurements during the start-up mode. During this step,readings such as vibration might be omitted in order to make best use ofthe limited bandwidth system. In step 302 the motor is started in usingthe output voltage from drive 22 configured to be in the what isintended to be the forward rotational direction. In step 303 controller24 monitors the downhole gauge 30 readings during starting of the motor10. After controller 24 starts the motor 10 and observes the downholegauge 30 readings to determine whether rotation is detected, and ifrotation is detected, the actual rotational direction. In step 304, andpreferably once enough time has passed to be confident of the readingsfrom the downhole gauge 30, for example after several telemetry updates,perhaps a minute, the controller 24 compares the readings from thedownhole gauge with the intended operating direction. If they are thesame, the downhole gauge 30 is put back into normal mode and thecontroller 24 indicates to the operator that starting was successful andin step 305 the phase settings are saved. If in step 304 the readingsfrom the downhole gauge 30 and the intended forward rotational directionare not the same, the controller 24 stops the motor in step 306, and instep 307 drive 22 outputs the motor voltage phase sequence for theopposite rotational direction and in step 308 controller 24 restartsmotor 10 in the opposite direction. In step 304 controller 24 againchecks the downhole gauge 30 readings to confirm correct direction or tosignal a fault. If it is correct, controller 24 preferably saves thecorrect phase sequence into storage, such as non-volatile memorystorage, in step 305 so that it can always start correctly the firsttime after any restartable surface alarm or power loss, or after aplanned stop. Once the correct phase sequence has been saved drive 22takes over the control of motor 10 in step 309.

It should be appreciated by one skilled in the art that variations ofthe processes and apparatuses described herein above may be easilyaccomplished and remain within the scope of embodiments of the presentdisclosure. For example, in an alternative embodiment the downhole gaugemay be configured to automatically switch into starting mode whenever itsenses that the motor is not turning, and revert to normal mode a fewminutes after starting is successful, thus avoiding the need forcommunication to the downhole gauge from surface. Two binary bits fromthe apparatus of the present disclosure are sufficient to indicaterotation and direction. The bits occupy very little bandwidth and mightbe transmitted in all or occasional telemetry frames throughcommunications system 51, without a special mode.

In certain embodiments, the controller 24 of the present disclosure iscapable of advising an operator of incorrect rotational condition of themotor 10 and further to allow the operator to decide whether to stop andrestart the motor, rather than a fully automated process. An example ofwhere this method embodiment is useful is if it is preferred tophysically rewire the phase connections at the drive so that the pumpwill start correctly when the controller is left to operate in itsnormal rotational direction.

It is known in the art that it is sometimes difficult to start a pump'srotational movement, such as when it is filled (or partially filled)with sand. As is known in the art, a rocking start is a sequence offorward and reverse starts at different levels of intensity and is usedto try and free the pump of sand. Excessive starting intensity androcking risks damaging the pumping system including breaking of themotor or pump shaft. In such cases, aspects of the present disclosureadvantageously allow an operator to know if the pump shaft has movedduring a start attempt, and provides a further indication of theseverity of the “sticking” and how to proceed such as extending,changing or stopping the rocking sequence. In embodiments related toencoder 201, the shaft encoder transmitting the shaft angle at 10-20second intervals to the controller will permit such information to beinterpreted.

As herein described herein above with respect to the prior art controlof downhole pumping systems, prior art downhole gauges do not have thebandwidth to transmit shaft angle using known sensors at a sufficiencyhigh rate for sensor control of the motor. In accordance withembodiments the present disclosure described herein above, an analoguesignal indicating shaft angle can be transmitted to surface controlsystems by methods as now described. By way of an example, progressivecavity pumps rotate at only a few hundred rpm, therefore the shaftrotation rate is only a few Hertz (Hz). Still considering the sameexample, when the shaft is rotating at 240 rpm the rate is 4 Hz. Thisrate may be low enough for a downhole gauge to transmit a (preferablysinusoidal) modulation, in this example at 4 Hz, of the gauge supplyvoltage or load current, and yet be separable from the sending ofdownhole data using a telemetry system by employing known filteringmethods. The surface control equipment of the present disclosure can usethe sinusoidal variation to determine the shaft angle, in conjunctionwith a rotational direction measurement as hereinbefore described.Alternatively, if a separate wire (not shown) is used for telemetry tosurface, commonly known as an instrument or tubing encapsulated cable(TEC) cable, the telemetry can be at a relatively high rate and themodulation used to cover a wide range of shaft speeds. It is importantto note, from a practical perspective, any such means of establishing aremote shaft sensor for motor control purposes must recognize thatdownhole equipment has a significant probability of failure over itslifetime and of infant mortality. In such situations the surface drivewould need to have a fall-back sensorless method of control if a costlyworkover is to be avoided.

In addition to the advantages described herein above, during operationof the rotational sensor of the present disclosure, there exists manyother conditions that the present disclosure may provide. For example, astall condition of the motor shaft 100 may be detected, such as when thedrive 22 loses control of a downhole permanent magnet motor. Warning ofthe stall condition from the present disclosure will allow thecontroller 24 to quickly stop the motor 10, preventing the motor rotorfrom overheating due to eddy currents inducted by the rotating statorfield, and potential subsequent demagnetization. Another such advantageof embodiments of the present disclosure is the ability to detectbackspin of the pump. It is known that in certain downhole pumpingsystems that in the event of power failure, or other types of failures,there exists a column of production fluid in the production tubing 3above the pump 12. As the column of fluid drains back into the wellborethe pump may be driven backwards, or backspin, and drive the motor inthe reverse direction thereby. In certain instances, such as in systemsusing permanent magnet motors, the motor may produce a hazardous voltagein a backspin condition. The backspin condition will continue, with thefluid column in the tubing draining, until the forces in the system comeinto balance. In addition, the operator may need to know when thedraining and backspin has ceased, or at least slowed, before restartingthe motor. Embodiments of the present disclosure provide an operatorwith such rotational parameters as shaft movement, direction and speed,information of the motor and pump. Another advantage of embodiments ofthe present disclosure is the ability to detect frictional changes,which translate directly into acceleration and speed changes, within thesystem, such as a rubbing rotor. It should be appreciated by thoseskilled in the art that embodiments of the present disclosure employingencoder 201 provide angular shaft speed from which quadrant to quadrant(between coils 107A, 107B, 107C, 107D) variations, and accelerationthereby, may be determined that may be attributed to such frictionalchanges.

Although described herein with reference to synchronous permanent magnetmotors, the present disclosure is particularly useful with asynchronous(induction) motors as used widely with ESPs. Such induction motors aretypically operated by setting the electrical frequency and voltage ofthe motor. As is well known in the art, the speed of an induction motoroperated at constant frequency will vary with load. Surface controllerscan estimate motor speed in order to adjust the frequency to achieve aconstant speed. However, a downhole rotational sensor system of thepresent disclosure will permit transmission of speed or speed change soas to give direct feedback to the drive 22.

While the foregoing is directed to embodiments of the presentdisclosure, other and further embodiments of the disclosure may bedevised without departing from the basic scope thereof, and the scopethereof is determined by the claims that follow.

1. An apparatus, comprising: an electrical submersible pump assemblyincluding a motor, a shaft, a pump, and at least one sensor systempositioned to measure a rotational parameter of the shaft; a processingsystem being configured to determine one or more measures of therotational parameter of the shaft from a signal output from the at leastone sensor system; a control system to cause the shaft to rotate in afirst rotational direction, the processing system determines the firstrotational direction and then compares the first rotational direction toa desired rotational direction; and whereby the control system furthercauses the shaft to rotate alternatively between the desired rotationaldirection and the opposite rotational direction.
 2. (canceled) 3.(canceled)
 4. An apparatus of claim 1, whereby the control systemfurther causes the shaft to rotate in the desired rotational direction.5. An apparatus of claim 1, whereby the control system further causesthe shaft to rotate in an opposite rotational direction to the desiredrotational direction.
 6. (canceled)
 7. An apparatus, comprising: anelectrical submersible pump assembly including a motor, a shaft, a pump,and at least one sensor system positioned to measure a rotationalparameter of the shaft wherein the at least one sensor system comprisesa transmitter assembly and a receiver assembly and wherein thetransmitter assembly is attached to the shaft and the receiver assemblyis attached to a stationary portion of the motor.
 8. (canceled)
 9. Anapparatus of claim 47, wherein the rotational parameter includes arotational direction of the shaft.
 10. An apparatus, comprising: anelectrical submersible pump assembly including a motor, a shaft, a pump,and at least one sensor system positioned to measure a rotationalparameter of the shaft wherein the rotational parameter of the shaftincludes at least one of a rotational speed, a rotational direction, anacceleration or an angular position.
 11. A method, comprising: providingan electrical submersible pump assembly including a motor, a shaft, apump, at least one sensor system positioned to measure a rotationalparameter of the shaft, a processing system, and a control system,determining a rotational parameter of the shaft from an output signalfrom the at least one sensor system; determining a first direction ofrotation of the shaft responsive to the output signal from the at leastone sensor system; and wherein the determining the first direction ofrotation of the shaft responsive to the output signal from the at leastone sensor system further includes: causing the shaft to rotate in thefirst direction of rotation and then comparing the first direction ofrotation to a desired rotational direction.
 12. (canceled) 13.(canceled)
 14. A method of claim 11, whereby the control system furthercauses the shaft to rotate in the desired rotational direction.
 15. Amethod of claim 11, whereby the control system further causes the shaftto rotate in an opposite rotational direction to the desired rotationaldirection.
 16. A method of claim 11, whereby the control system furthercauses the shaft to rotate alternatively between the desired rotationaldirection and the opposite rotational direction.
 17. A method of claim11, wherein the determining of a rotational parameter includesdetermining a rotational direction, a rotational speed, an accelerationand an angular position of the shaft.
 18. A method of claim 11, wherebythe control system further controls the shaft to rotate based on therotational parameter.
 19. A method of claim 11, further comprisingcommunicating the output signal to the processing system via a telemetrysystem, a TEC cable or a limited bandwidth system.
 20. A method of claim11, further comprising detecting an operating condition of the pump. 21.A method of claim 20, wherein the operating condition of the pumpincludes a stall condition, a backspin condition, a speed fluctuationcondition, a stuck condition, a stopped condition, and a constant speedcondition.